Rotating and reciprocating swivel apparatus and method

ABSTRACT

What is provided is a method and apparatus wherein a rotating and reciprocating swivel of adjustable stroke length and shearable by ram blow out preventers can be detachably connected to an annular blowout preventer thereby separating the lower wellbore from the riser. In one embodiment the mandrel of the swivel being comprised of double box end joints and using double pin end subs to connect a plurality of such mandrel joints together.

CROSS-REFERENCE TO RELATED APPLICATIONS

This is a non-provisional of U.S. provisional patent application Ser.No. 61/620,207, filed Apr. 4, 2012, which is incorporated herein byreference and priority of/to which is hereby claimed.

U.S. patent application Ser. No. 12/682,912, entitled Rotating AndReciprocating Swivel Apparatus and Method, having a Sep. 20, 2010 filingor section 371(c) date, is hereby incorporated herein by reference.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable

REFERENCE TO A “MICROFICHE APPENDIX”

Not applicable

BACKGROUND

In deepwater drilling rigs, marine risers extending from a wellheadfixed on the ocean floor have been used to circulate drilling fluid ormud back to a structure or rig. The riser must be large enough ininternal diameter to accommodate a drill string or well string thatincludes the largest bit and drill pipe that will be used in drilling aborehole. During the drilling process drilling fluid or mud fills theriser and wellbore.

BRIEF SUMMARY

The method and apparatus of the present invention solves the problemsconfronted in the art in a simple and straightforward manner.

One embodiment relates to a method and apparatus for deepwater rigs. Inparticular, one embodiment relates to a method and apparatus forperforming downhole operations at a time when the annular blow outpreventer is closed.

In one embodiment displacement is contemplated in water depths in excessof about 5,000 feet (1,524 meters).

One embodiment provides a method and apparatus having a swivel which canoperably and/or detachably connect to an annular blowout preventerthereby separating the fluid or mud into upper and lower sections.

In one embodiment a swivel tool can be used having a sleeve or housingthat is rotatably and sealably connected to a mandrel. The swivel can beincorporated into a drill or well string.

In one embodiment the sleeve or housing can be fluidly sealed to and/orfrom the mandrel.

In one embodiment the sleeve or housing can be fluidly sealed withrespect to the outside environment.

In one embodiment the sealing system between the sleeve or housing andthe mandrel is designed to resist fluid infiltration from the exteriorof the sleeve or housing to the interior space between the sleeve orhousing and the mandrel.

In one embodiment the sealing system between the sleeve or housing andthe mandrel is designed to resist fluid infiltration from the interiorspace between the sleeve or housing and the mandrel to the exterior.

In one embodiment the sealing system between the sleeve or housing andthe mandrel has a substantially equal pressure ratings for pressurestending to push fluid from the exterior of the sleeve or housing to theinterior space between the sleeve or housing and the mandrel andpressures tending to push fluid from the interior space between thesleeve or housing and the mandrel to the exterior of the sleeve orhousing.

In one embodiment a swivel having a sleeve or housing and mandrel isused having at least one flange, catch, or upset to restrictlongitudinal movement of the sleeve or housing relative to the annularblow out preventer. In one embodiment a plurality of flanges, catches,or upsets are used. In one embodiment the plurality of flanges, catches,or upsets are longitudinally spaced apart with respect to the sleeve orhousing.

The swivel tool can be closed on by the annular blowout preventer(“annular BOP”). Typically, the annular BOP is located immediately abovethe ram BOP which ram BOP is located immediately above the sea floor andmounted on the well head. As an integral part of the string, the mandrelof the rotating and reciprocating tool supports the full weight, torque,and pressures of the entire string located below the mandrel.

In one embodiment, at least partly during the time the annular seal isclosed on the sleeve of the swivel, the drill or well string isintermittently stroked longitudinally during downhole operations, suchas in a hydraulic fracturing job.

In one embodiment the rotational speed is reduced during the timeperiods that reciprocation is not being performed. In one embodiment therotational speed is reduced from about 60 revolutions per minute toabout 30 revolutions per minute when reciprocation is not beingperformed.

In one embodiment, at least partly during the time the annular seal isclosed on the sleeve of the swivel, the drill or well string isreciprocated longitudinally. In one embodiment a reciprocation stroke ofabout 65.5 feet (20 meters) is contemplated. In one embodiment about20.5 feet (6.25 meters) of the stroke is contemplated for allowingaccess to the bottom of the well bore. In one embodiment about 35, about40, about 45, and/or about 50 feet (about 10.67, about 12.19, about13.72, and/or about 15.24 meters) of the stroke is contemplated forallowing at least one pipe joint-length of stroke during reciprocation.In one embodiment reciprocation is performed up to a speed of about 20feet per minute (6.1 meters per minute).

In one embodiment one or more brushes and/or scrapers are used in themethod and apparatus.

In one embodiment a mule shoe is used in the method and apparatus.

Catches

The annular BOP is designed to fluidly seal on a large range ofdifferent sized items—e.g., from 0 inches to 18¾ inches (0 to 47.6centimeters) (or more). However, when an annular BOP fluid seals on thesleeve of the rotating and reciprocating tool, fluid pressures on thesleeve's exposed effective cross sectional area exert longitudinalforces on the sleeve. These longitudinal forces are the product of thefluid pressure on the sleeve and the sleeve's effective cross sectionalarea. Where different pressures exist above and below the annular BOP(which can occur in completions having multiple stages), a netlongitudinal force will act on the sleeve tending to push it in thedirection of the lower fluid pressure. If the differential pressure islarge, this net longitudinal force can overcome the frictional forceapplied by the closed annular BOP on the sleeve and the frictionalforces between the sleeve and the mandrel. If these frictional forcesare overcome, the sleeve will tend to slide in the direction of thelower pressure and can be “pushed” out of the closed annular BOP. In oneembodiment catches are provided which catch onto the annular BOP toprevent the sleeve from being pushed out of the closed annular BOP.

For example, lighter sea water above the annular BOP seal and heavierdrilling mud, or weighted pills, and/or weighted completion fluid, or acombination of all of these can be below the annular BOP requiring anincreased pressure to push such fluids from below the annular BOP upthrough the choke line and into the rig (at the selected flow rate).This pressure differential (in many cases causing a net upward force)acts on the effective cross sectional area of the tool defined by theouter diameter of the string (or mandrel) and the outer diameter of thesleeve. For example, the outer sealing diameter of the tool sleeve canbe 9¾ inches (24.77 centimeters) and the outer diameter of the toolmandrel can be 7 inches (17.78 centimeters) providing an annular crosssectional area of 9¾ inches (24.77 centimeters) OD and 7 inches ID(17.78 centimeters). Any differential pressure will act on this annulararea producing a net force in the direction of the pressure gradientequal to the pressure differential times the effective cross sectionalarea. This net force produces an upward force which can overcome thefrictional force applied by the annular BOP closed on the tool's sleevecausing the sleeve to be pushed in the direction of the net force (orslide through the sealing element of the annular BOP). To resist slidingthrough the annular BOP, catches can be placed on the sleeve whichprevent the sleeve from being pushed through the annular BOP seal.

In any of the various embodiments, the following differential pressures(e.g., difference between the pressures above and below the annular BOPseal) can be axially placed upon the sleeve or housing against which thecatches can be used to prevent the sleeve from being axially pushed outof the annular BOP (even when the annular BOP seal has been closed)—inpounds per square inch: 500, 750, 1000, 1250, 1500, 1750, 2000, 2250,2500, 2750, 3000, 3250, 3,500, 3750, 4,000, 4,250, 4,500, 4,750, 5,000,10,000 or greater (3,450, 5,170, 6,900, 8,620, 10,340, 12,070, 13,790,15,510, 17,240, 18,960, 20,690, 22,410, 24,130, 25,860, 27,700, 29,550,31,400, 33,240, 35,090, 36,940, 73,880 kilopascals). Additionally,ranges between any two of the above specified pressures arecontemplated. Additionally, ranges above any one of the above specifiedpressures are contemplated. Additionally, ranges below any one of theabove specified pressures are contemplated. These differential pressurescan be higher below the annular BOP seal or above the annular BOP seal.

Quick Lock/Quick Unlock

After the sleeve and mandrel have been moved relative to each other in alongitudinal direction, a downhole/underwater locking/unlocking systemis needed to lock the sleeve in a longitudinal position relative to themandrel (or at least restricting the available relative longitudinalmovement of the sleeve and mandrel to a satisfactory amount compared tothe longitudinal length of the sleeve's effective sealing area).Additionally, an underwater locking/unlocking system is needed which canlock and/or unlock the sleeve and mandrel a plurality of times while thesleeve and mandrel are underwater.

In one embodiment is provided a system wherein the underwater positionof the longitudinal length of the sleeve's sealing area (e.g., thenominal length between the catches) can be determined with enoughaccuracy to allow positioning of the sleeve's effective sealing area inthe annular BOP for closing on the sleeve's sealing area. After thesleeve and mandrel have been longitudinally moved relative to each otherwhen the annular BOP was closed on the sleeve, it is preferred that asystem be provided wherein the underwater position of the sleeve can bedetermined even where the sleeve has been moved outside of the annularBOP.

In one embodiment is provided a quick lock/quick unlock system forlocating the relative position between the sleeve and mandrel. Becausethe sleeve can reciprocate relative to the mandrel (i.e., the sleeve andmandrel can move relative to each other in a longitudinal direction), itcan be important to be able to determine the relative longitudinalposition of the sleeve compared to the mandrel at some point after thesleeve has been reciprocated relative to the mandrel. For example, invarious uses of the rotating and reciprocating tool, the operator maywish to seal the annular BOP on the sleeve sometime after the sleeve hasbeen reciprocated relative to the mandrel and after the sleeve has beenremoved from the annular BOP.

To address the risk that the actual position of the sleeve relative tothe mandrel will be lost while the tool is underwater, a quicklock/quick unlock system can detachably connect the sleeve and mandrel.In a locked state, this quick lock/quick unlock system can reduce theamount of relative longitudinal movement between the sleeve and themandrel (compared to an unlocked state) so that the sleeve can bepositioned in the annular BOP and the annular BOP relatively easilyclosed on the sleeve's longitudinal sealing area. Alternatively, thisquick lock/quick unlock system can lock in place the sleeve relative tothe mandrel (and not allow a limited amount of relative longitudinalmovement). After being changed from a locked state to an unlocked state,the sleeve can experience its unlocked amount of relative longitudinalmovement.

In one embodiment is provided a quick lock/quick unlock system whichallows the sleeve to be longitudinally locked and/or unlocked relativeto the mandrel a plurality of times when underwater. In one embodimentthe quick lock/quick unlock system can be activated using the annularBOP.

In one embodiment the sleeve and mandrel can rotate relative to oneanother even in both the activated and un-activated states. In oneembodiment, when in a locked state, the sleeve and mandrel can rotaterelative to each other. This option can be important where the annularBOP is closed on the sleeve at a time when the string (of which themandrel is a part) is being rotated. Allowing the sleeve and mandrel torotate relative to each other, even when in a locked state, minimizeswear/damage to the annular BOP caused by a rotationally locked sleeve(e.g., sheer pin) rotating relative to a closed annular BOP. Instead,the sleeve can be held fixed rotationally by the closed annular BOP, andthe mandrel (along with the string) rotates relative to the sleeve.

In one embodiment, when the locking system of the sleeve is in contactwith the mandrel, locking/unlocking is performed without relativerotational movement between the locking system of the sleeve and themandrel—otherwise scoring/scratching of the mandrel at the location oflock can occur. In one embodiment, this can be accomplished byrotationally connecting to the sleeve the sleeve's portion of quicklock/quick unlock system. In one embodiment a locking hub is providedwhich is rotationally connected to the sleeve.

In one embodiment a quick lock/quick unlock system on the rotating andreciprocating tool can be provided allowing the operator to lock thesleeve relative to the mandrel when the rotating and reciprocating toolis downhole/underwater. Because of the relatively large amount ofpossible stroke of the sleeve relative to the mandrel (i.e., differentpossible relative longitudinal positions), knowing the relative positionof the sleeve with respect to the mandrel can be important. This isespecially true at the time the annular BOP is closed on the sleeve. Thelocking position is important for determining relative longitudinalposition of the sleeve along the mandrel (and therefore the trueunderwater depth of the sleeve) so that the sleeve can be easily locatedin the annular BOP and the annular BOP closed/sealed on the sleeve.

During the process of moving the rotating and reciprocating toolunderwater and downhole, the sleeve can be locked relative to themandrel by a quick lock/quick unlock system. In one embodiment the quicklock/quick unlock system can, relative to the mandrel, lock the sleevein a longitudinal direction. In one embodiment the sleeve can be lockedin a longitudinal direction with the quick lock/quick unlock system, butthe sleeve can rotate relative to the mandrel during the time it islocked in a longitudinal direction. In one embodiment the quicklock/quick unlock system can simultaneously lock the sleeve relative tothe mandrel, in both a longitudinal direction and rotationally. In oneembodiment the quick lock/quick unlock system can, relative to themandrel, lock the sleeve rotationally, but at the same time allow thesleeve to move longitudinally.

General Embodiments

In one embodiment the mandrel is comprised of a plurality of joints ofpiping/tubing which are threadably connected to each other.

In one embodiment a sleeve/housing is rotatably and slidably connectedto the mandrel.

In one embodiment the sleeve/housing includes a pair of spaced apartsealing units which sealingly engage the sleeve/housing relative to theexternal surface of the mandrel during the time period the sleeve isslidably and/or rotatably connected to the mandrel.

In one embodiment the sleeve/housing can remain stationary while aportion of the mandrel is moved longitudinally or stroked relative tothe sleeve.

In one embodiment the mandrel can be stroked or passed through thereciprocable and rotatable sleeve/housing while the sleeve/housing ismaintained stationary relative to an annular blow out preventer, andwith the annular blow out preventer maintaining a seal on the sealingarea of the sleeve/housing. With the seal between the sleeve/housing andthe mandrel, in combination with the seal between the annular of theannular blow out preventer and the sealing area of the sleeve, a fluidseal can be maintained between above and below the annular seal of theannular blow out preventer even when the mandrel is stroked and/orrotating. Such allows any drill string, tools, and/or other itemslocated below the mandrel to be rotated and/or reciprocated while theclosed annular blow out preventer maintains a seal on the wellbore, andwithout the annular seal of the annular blowout preventer beingsubjected to differential movement which differential movement candamage the annular seal.

One embodiment allows the stroking area of the mandrel to slide relativeto the sleeve/housing, thereby providing the benefit of longitudinalmovement and/or rotation but substantially eliminating differentialmovement of any item in contact with the closed annular sealing elementrelative to the closed annular sealing element. Accordingly, the risk ofdamage to the closed annular sealing element is substantiallyeliminated.

Shearable Mandrel Design

One embodiment provides a downhole swivel tool comprising a longitudinalmandrel with a longitudinal interior passageway, the mandrel having asleeve/housing slidably connected to the mandrel, wherein the mandrelcan rotate and reciprocate/stroke relative to the sleeve, and whereinsleeve/housing and the mandrel is sealed in a longitudinal direction.

There is a long felt but unsolved need to have a swivel tool including amandrel that is shearable relative to a plurality of stacked ram typeblow out preventers regardless of the position of the mandrel relativeto the stack of ram type blow out preventers.

In one embodiment, within the stroking length of the mandrel, theexterior mandrel sealing surface can be kept substantially at a uniformdiameter to maintain a longitudinal seal with respect to thesleeve/housing.

One embodiment of the swivel tool provides a mandrel, within thestroking length of the mandrel, the exterior mandrel sealing surfacebeing kept at a substantially uniform diameter to maintain alongitudinal seal with respect to the sleeve/housing, within thisstroking length the mandrel having a interior axial passageway, theinterior axial passageway having first and second diameters, the firstdiameter being larger than the second diameter, with the longitudinalspacing of the sections of mandrel having first diameter to sectionshaving second diameter being such that at any one point at least one ramof a plurality of stacked ram blow out preventers would attempt to sheara section of the mandrel having the first diameter thereby ensuringcontinuous shearability of the mandrel.

In one embodiment the exterior sealing surface of the mandrel can haveone or more recessed areas. In one embodiment the sleeve/housing canhave a plurality of spaced apart sealing units, such that at any onetime during stroking/rotation of the mandrel relative to the sleeve atleast one of the spaced apart sealing units maintains a seal between themandrel and the sleeve even when the other sealing unit is located abovea recessed area of the mandrel.

In one embodiment the one or more recessed areas can be used tovertically support the mandrel when making up or breaking out themandrel when at a rig bore.

In one embodiment the one or more recessed areas can be located onpin/male by pin/male joints of mandrel which pin/male by pin/male pinjoints have a larger wall thickness relative to the wall thickness ofthe box/female by box/female joints of mandrel.

In one embodiment the smallest diameter of the one or more recessedareas can be between the diameter of the axial passage through thepin/male by pin/male joint and the axial diameter of the axial passageof the box/female by box/female joint.

In one embodiment the mandrel is constructed of multiple joints ofbox/female to box/female ends having thin walled tubing/piping meetingpredefined shearing constraints for a specified ram type blow outpreventer.

Because of manufacturing ease, typically the longitudinal passagethrough a joint of tubular is substantially the same size.

In detachably threaded connections (e.g., male and female threads) forjoints of tubulars, the male portion of the connection being concentricwith the female portion of the connection, with the male portion beinginterior to the female portion of such connection, the largestlongitudinal passage through the male portion of such connection isnecessarily smaller than the largest longitudinal passage through thefemale portion of the connection.

With a joint of tubular having a pin/male by box/female end, the largestpossible size of longitudinal axial passage is controlled by the size ofthe smaller interiorly concentric pin end connection. With a joint oftubular having a box/female by box/female end connection, now thelargest possible size of longitudinal passage is controlled by the sizeof the exteriorly concentric box/female end connection, and can belarger than the size of a mating interiorly concentric pin/male endconnection.

Now a mandrel formed by such combination of joints of box/female bybox/female end joints alternatively connected by pin/male by pin/maleend joints of tubular can have spaced apart thin walled portions thatare easily shearable by ram type blow out preventers. The spacing apartof the thin walled portions can be on opposing sides of the pin/male bypin/male joints of mandrel. The alternative box/female by box/femalewith pin/male by pin/male can have length spacings such that at any onepoint at least one ram of the plurality of stacked ram blow outpreventers would attempt to shear a thin walled portion of the mandrelthereby ensuring continuous shearability of the mandrel.

The mandrel can comprise one or more joints of tubing or piping withbox/female by box/female ends and each joint being approximately 30 feetin length.

Connecting the box/female by box/female ended joints of tubing/pipingcan be joints of pipe which are pin/male by pin/male type connections,with each of these pin by pin joints being approximately 30 inches inlength.

The mandrel stroking area can include a longitudinal length of combinedplurality of mandrel joints where such joints have a substantiallyuniform outer sealing diameter. Threading can be used to detachablyconnect the mandrel joints to each other.

In one embodiment a reduced diameter groove/area can be machined on thesurface of one or more of the stroking joints of mandrel. In oneembodiment the reduced diameter groove/area is provided in the pin bypin stroking joint of mandrel.

In one embodiment the reduced diameter groove/area can be used to liftor lower together the tool with bottleneck elevators.

In one embodiment an annular seal between joints of mandrel can beactivated by rotating one mandrel joint relative to a second mandreljoint.

In one embodiment is provided plurality of joints of mandrel where thebox or female end has a tapered end shoulder which cooperates with atapered shoulder of a mating pin/male end joint to prevent the end ofthe female/box portion from flaring or expanding when tightened. In oneembodiment shoulder of pin end and shoulder of box end are tapered. Inone embodiment the tapers are substantially parallel to each other andtend to cause the box end to be squeezed/directed towards the internalaxial passageway of the mandrel.

Ratio Between Wall Thickness of Pin by Pin to Box by Box End Joints

In one embodiment the ratio between wall thicknesses of mating joints ofmandrel are least 2:1, 3:1, 4:1, 5:1, 6:1, 7:1, 8:1, 9:1, 10:1, 12:1,14:1, 16:1, 18:1, and 20:1. In various embodiments the ratio can bebetween any two of the specified ratios. In one embodiment, the wallthicknesses of the box/female by box/female end joints are designed tobe shearable in the ram blow out preventers.

In one embodiment the different wall thicknesses can be seen in Pin/maleby Pin/male joints of mandrel compared to Box/female by Box/femalejoints of mandrel.

In this embodiment the wall box by box end joints' wall thicknesses aredesigned to be shearable in the ram blow out preventers.

Mandrel Comprised of Double Pin End Joints and Double Box End Joints

In one embodiment the mandrel can be comprised of a plurality of doublebox/female by box/female end joints connected by double pin/male bypin/male end joints, wherein the double pin end joints are spaced apartat least 4, 5, 6, 7, 8, 9, 10, 12, 14, 16, 18, 20, 25, 30, 35, 40, 45,50, 55, 60, 65, 70, 75, 80, 84, 85, 90, 95, and 100 feet. In variousembodiments the double pin end joints can be spaced between any two ofthe above specified lengths.

In various embodiments the double pin end joints, in length, can be lessthan 48 inches, 46, 45, 44, 42, 40, 38, 36, 34, 32, 30, 28, 26, and 24inches. In various embodiments the length of the double pin end jointscan be between any two of the above specified lengths.

Sleeve with Two Spaced Apart Seal Units Dealing with Recessed Areas ofMandrel

In one embodiment, within the stroking length of the exterior sealingarea of the mandrel with respect to the sleeve/housing includes at leastone recessed area in the external sealing surface of the mandrel (whichrecessed area is used for supporting the weight of the drill string andswivel tool during the process of tripping in the swivel tool into thewell bore). In one embodiment the mandrel includes a plurality ofrecessed areas spaced apart the longitudinal length of the mandrel andwithin the stroking length of the sleeve/housing.

In various embodiments such recessed area or areas can cause a seal unitin the sleeve/housing to lose partial or complete sealing between sleeveand mandrel when such seal unit passes over the recessed area. Invarious embodiments, such a partial or complete loss of sealing of oneseal unit is compensated by the remaining seal of the other spaced apartsealing unit (which maintains a seal between sleeve and mandrel on theexternal sealing surface of the mandrel).

In various embodiments, one or more recessed areas in the externalsealing portion of the mandrel includes at least one transition piecewhich is of a softer material than the material comprising the externalsealing area of the mandrel, for example teflon compared to steel. Otherexamples include rubber, viton, plastic, polymer,

In one embodiment, the mandrel can be stroked/reciprocated with respectto the sleeve/housing causing one or more recessed areas in the externalsealing area of the mandrel to pass through the sleeve. In oneembodiment, with the sleeve having first and second spaced apartsealing, the mandrel is moved relative to the sleeve wherein:

-   -   (1) first and second seal units maintain independent sealing        between sleeve and mandrel;    -   (2) first seal unit moves across recessed area of mandrel but        second seal unit maintains seal between sleeve and mandrel; or,    -   (3) second seal unit moves across recessed area of mandrel but        first seal unit maintains seal between sleeve and mandrel.

In one embodiment, the longitudinal length of one or more recessed areasin the mandrel can be between 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 14,16, 18, 20, 22, 24, 26, 28, 30, 32, 34, 36, 40, 45, 50 inches; and thespacing between the spaced apart seal units in the sleeve/housing.

Sealing Inserts for Thin Walled Sections

One embodiment includes inserts for the thin walled sections ofbox/female by box/female joints of mandrel.

One embodiment has the inserts being slidable relative to the joint ofmandrel in which the insert is contained.

One embodiment has the inserts having an internal bore transition, fromsmall to large bore internal flow passage.

One embodiment includes the insert with an annular recess for at leastpartially containing an internal sealing unit.

General Method of Making Up Stroking Mandrel when on Rig

In one embodiment is provided a method of determining the strokinglength of a rotating and reciprocable swivel tool at a drilling rig orplatform having a floor, comprising the steps of:

(a) providing a swivel tool, the swivel tool comprising a mandrel and asleeve, the mandrel being rotatable and reciprocable relative to thesleeve/housing, the mandrel having a first stroke length relative to thesleeve/housing;

(b) supporting in a substantially vertical direction the swivel tool atthe rig;

(c) adding a mandrel joint to the top of the mandrel, such additionaljoint increasing the stroking length of the mandrel relative to thefirst stoking length;

(d) lowering the swivel tool and again supporting in a verticaldirection the swivel tool in a substantially vertical direction on therig; and

(e) repeating steps “c” and “d” unit the final stroking length of themandrel relative to the sleeve/housing is at least 100 feet.

In various embodiments the steps “c” and “d” can be repeated until thefinal stroking length can be greater than about 100, 150, 200, 250, 300,350, 400, 450, 500, 550, 600, 700, 800, 900, 1000, 1200, 1400, 1500,1600, 1800, and 2000 feet, or any stroke lengths between any two of thespecified stroke lengths.

In various embodiments a plurality of the mandrel joints includerecessed areas in the exterior sealing surface, and during step “c” oneof these recessed areas is used to support the swivel tool in asubstantially vertical direction.

In one embodiment the plurality of recessed areas can include softmaterial transition sections.

In various embodiments the upper portions of the recessed areas can befrustoconical.

In various embodiments the upper portions of the recessed areas can betapered.

On embodiment comprises a method of increasing stroke length of themandrel while located on rig or platform.

One embodiment comprises a method of making up the mandrel while on rigor platform.

General Method Steps

In one embodiment the method can comprise the following steps:

(a) lowering the rotating and reciprocating tool to the annular BOP, thetool comprising a sleeve and a mandrel;

(b) after step “a”, having the annular BOP close on the sleeve;

(c) after step “b”, causing relative longitudinal movement between thesleeve and the mandrel; and

(d) after step “c”, performing wellbore operations.

In various embodiments the method can include one or more of thefollowing additional steps:

(1) after step “c”, moving the sleeve outside of the annular BOP;

(2) after step “(1)”, moving the sleeve inside of the annular BOP andhaving the annular BOP close on the sleeve;

(3) after step “(2)”, causing relative longitudinal movement between thesleeve and the mandrel.

In one embodiment, during step “a”, the sleeve is longitudinally lockedrelative to the mandrel.

In one embodiment, after step “b”, the sleeve is unlocked longitudinallyrelative to the mandrel.

In one embodiment, after step “c”, the sleeve is longitudinally lockedrelative to the mandrel.

In one embodiment, during step “c” operations are performed in thewellbore.

In one embodiment, during step “(3)” operations are performed in thewellbore.

In one embodiment, during step “c” the tool is fluidly connected to astring having a bore and fluid is pumped through at least part of thestring's bore.

In one embodiment, during step “(3)” the tool is fluidly connected to astring having a bore and fluid is pumped through at least part of thestring's bore.

In one embodiment, during step “c” the tool is fluidly connected to astring having a bore and fluid is pumped through at least part of thestring's bore and fracturing operations performed.

In one embodiment, during step “(3)” the tool is fluidly connected to astring having a bore and fluid is pumped through at least part of thestring's bore and fracturing operations performed.

In one embodiment, longitudinally locking the sleeve relative to themandrel shortens an effective stroke length of the sleeve from a firststroke to a second stroke.

In one embodiment, during step “a”, the mandrel can freely rotaterelative to the sleeve.

In one embodiment, after step “b”, the mandrel can freely rotaterelative to the sleeve.

In one embodiment, after step “c”, the mandrel can freely rotaterelative to the sleeve.

To provide the completion engineers with the flexibility:

(a) to use the rotating and reciprocating tool while the annular BOP issealed on the sleeve and while taking return flow up the choke or killline (i.e., around the annular BOP); or

(b) to open the annular BOP and take returns up the subsea riser (i.e.,through the annular BOP); or

(c) to open the annular BOP and move the completion string with theattached rotating and reciprocating tool out of the annular BOP (such aswhere the completion engineer wishes to use a jetting tool to jet theBOP stack or perform other operations requiring the completion string tobe raised to a point beyond where the effective stroke capacity of therotating and reciprocating tool can absorb the upward movement by thesleeve moving longitudinally relative to the mandrel) and, at a laterpoint in time, reseal the annular BOP on the sleeve of the rotating andreciprocating tool (bypassing the top-drive unit).

In another embodiment the method can comprise the following steps:

(a) lowering the rotating and reciprocating tool to the annular BOP, thetool comprising a sleeve and mandrel;

(b) after step “a”, having the annular BOP close on the sleeve;

(c) after step “b”, causing relative longitudinal movement between thesleeve and the mandrel; and

(d) during and/or after step “c”, performing wellbore operations.

In various embodiments the method can include one or more of thefollowing additional steps:

(1) after step “c”, moving the sleeve outside of the annular BOP;

(2) after step “(1)”, moving the sleeve inside of the annular BOP andhaving the annular BOP close on the sleeve;

(3) after step “(2)”, causing relative longitudinal movement between thesleeve and the mandrel.

In one embodiment, during step “a”, the sleeve is longitudinally lockedrelative to the mandrel.

In one embodiment, after step “b”, the sleeve is unlocked longitudinallyrelative to the mandrel.

In one embodiment, after step “c”, the sleeve is longitudinally lockedrelative to the mandrel.

In one embodiment, during step “c” operations are performed in thewellbore.

In one embodiment, during step “(3)” operations are performed in thewellbore.

In one embodiment, during step “c” the tool is fluidly connected to astring having a bore and fluid is pumped through the choke and/or killof the BOP to the wellbore and returned through at least part of thestring's bore up to the rig through a right angle swivel fluid diverter.

In one embodiment, during step “(3)” the tool is fluidly connected to astring having a bore and fluid is pumped through the choke and/or killof the BOP to the wellbore and returned through at least part of thestring's bore up to the rig through a right angle swivel fluid diverter.

In one embodiment, longitudinally locking the sleeve relative to themandrel shortens an effective stroke length of the sleeve from a firststroke to a second stroke.

In one embodiment, during step “a”, the mandrel can freely rotaterelative to the sleeve.

In one embodiment, after step “b”, the mandrel can freely rotaterelative to the sleeve.

In one embodiment, after step “c”, the mandrel can freely rotaterelative to the sleeve.

To provide the completion engineers with the flexibility:

(a) to use the rotating and reciprocating tool while the annular BOP issealed on the sleeve and while pumping fluid through the choke or killline (i.e., around the annular BOP), and fluid is returned through atleast part of the string's bore up to the rig through a right angleswivel fluid diverter; or

(b) to open the annular BOP and take returns up the subsea riser (i.e.,through the annular BOP); or

(c) to open the annular BOP and move the completion string with theattached rotating and reciprocating tool out of the annular BOP (such aswhere the completion engineer wishes to use a jetting tool to jet theBOP stack or perform other operations requiring the completion string tobe raised to a point beyond where the effective stroke capacity of therotating and reciprocating tool can absorb the upward movement by thesleeve moving longitudinally relative to the mandrel) and, at a laterpoint in time, reseal the annular BOP on the sleeve of the rotating andreciprocating tool.

The drawings constitute a part of this specification and includeexemplary embodiments to the invention, which may be embodied in variousforms.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

For a further understanding of the nature, objects, and advantages ofthe present invention, reference should be had to the following detaileddescription, read in conjunction with the following drawings, whereinlike reference numerals denote like elements and wherein:

FIG. 1 is a schematic diagram showing a deep water drilling rig withriser and annular blowout preventer.

FIG. 2 is another schematic diagram of a deep water drilling rig showinga rotating and reciprocating swivel detachably connected to an annularblowout preventer, along with a ram blow out preventer mounted in thechristmas tree below the annular blowout preventer.

FIG. 3 is a perspective view of a conventionally available annularblowout preventer.

FIG. 4 is a sectional view cut through the annular and ram blow outpreventers of FIG. 2 with the annular seal closed on the sleeve of therotating and reciprocating swivel.

FIG. 5 is a schematic view of one embodiment of a mandrel which includesa plurality of double box end joints connected by a plurality of mandrelsubs.

FIG. 6 is a perspective view of one embodiment of a rotating andreciprocal swivel with sectional mandrel having joints incorporating pinend tip sealing configuration.

FIG. 7 is a side view of the rotating and reciprocal swivel of FIG. 6where the sleeve is located in its lowermost position, and the center ofgravity of the swivel is identified.

FIGS. 8A, 8B, and 8C are perspective views of the rotating andreciprocal swivel of FIG. 6 where respectively the sleeve is located inits lowermost, mid stroke, and upper most positions.

FIG. 9 is a side view of the sectional mandrel having jointsincorporating pin end tip sealing configuration of FIG. 6.

FIG. 10 is a sectional view of the sectional mandrel having jointsincorporating pin end tip sealing configuration of FIG. 6.

FIG. 11A is a sectional view of the mandrel of FIG. 6 showing one of theconnection joints incorporating pin end tip sealing configuration.

FIG. 11B is an enlarged sectional view of the joint of FIG. 11A.

FIG. 12 is a sectional view of the mandrel of FIG. 6 showing a joint ofmandrel having two pin ends and two connecting joints incorporating pinend tip sealing configuration.

FIG. 13 is an rear end view of a seal for the mandrel joints.

FIG. 14 is a sectional view of the seal shown in FIG. 13.

FIG. 15 is an enlarged sectional view of the seal of FIG. 14.

FIG. 16 is a sectional view of the mandrel of FIG. 6 showing theuppermost connection joint incorporating pin end tip sealingconfiguration.

FIG. 17 is a sectional view of the mandrel of FIG. 6 showing thelowermost connection joint incorporating pin end tip sealingconfiguration.

FIG. 18 is a sectional view of the mandrel of FIG. 6 showing a doublefemale end connection joint for receiving the pin end tip sealingconfiguration of one embodiment.

FIG. 19 is an enlarged view of a circumferential recess for receivingthe pin end tip sealing configuration of one embodiment.

FIG. 20 is an enlarged view of an end shoulder for limiting movement ofthe slidable sealing block of one embodiment.

FIG. 21 is a sectional view of the mandrel of FIG. 6 showing a doublefemale end connection joint for receiving the pin end tip sealingconfiguration of one embodiment, but with the slidable sealing blocksomitted.

FIG. 22 is an end view of the double female end connection joint of FIG.21.

FIG. 23 is a sectional side view of a slidable sealing block.

FIG. 24 is an end view of the slidable sealing block of FIG. 23.

FIG. 25 is a sectional view of a joint of mandrel having two pin endsand two connecting joints incorporating pin end tip sealingconfiguration

FIG. 26 is an enlarged view of one of the pin ends of the mandrel jointof FIG. 25.

FIG. 27 is a sectional view of the uppermost mandrel joint of themandrel shown in FIG. 6, with the joint having a pin end sealingconfiguration of one embodiment.

FIG. 28 is an enlarged view of one of the pin ends of the mandrel jointof FIG. 27.

FIG. 29 is a sectional view of the lowermost mandrel joint of themandrel shown in FIG. 6, with the joint having a pin end sealingconfiguration of one embodiment.

FIG. 30 is a left end view of the mandrel joint of Figure.

FIG. 31 is a right end view of the mandrel joint of FIG. 29.

FIG. 32 is an enlarged view of the area showing a pressure relief areabetween the interstitial space of the interior of the sleeve and theexterior of the mandrel.

FIG. 33 is a sectional view of the lowermost mandrel joint of themandrel shown in FIG. 6, with the joint having a pin end sealingconfiguration of one embodiment.

FIG. 34 is an enlarged view of one of the pin ends of the mandrel jointof FIG. 33, having the seal of one embodiment.

FIGS. 35 through 37 show the operation of mating tapered shoulders andends for the box and pin joints of the mandrel.

FIG. 38 shows a pin/male by pin/male mandrel joint with recess in itsexterior sealing surface being connecting to two female tubulars.

FIGS. 39 through 42 show various embodiments of the pin/male by pin/malemandrel joint with recess in its exterior sealing surface.

FIG. 43 is a side view of a sleeve of the mandrel shown in FIG. 6.

FIG. 44 is a sectional view of the sleeve shown in FIG. 43, with thesealing element for the pin end removed.

FIG. 45 is an enlarged sectional view of an end for the sleeve shown inFIGS. 43 and 44.

FIGS. 46 through 51 schematically show stroking and sealing of mandrelrelative to sleeve where mandrel has at least one recessed area inmandrel's external sealing surface.

FIG. 52A is a schematic view of the upper catch portion of sleeve wherethe upper seal is sealing on external sealing surface of mandrel.

FIG. 52B is a schematic view of the upper catch portion of sleeve wherethe upper seal is not sealing on external sealing surface of mandrel.

FIG. 53A is a section view of the lower catch portion of sleeve wherethe lower seal is sealing on external sealing surface of mandrel.

FIG. 53B is a section view of the lower catch portion of sleeve wherethe lower seal is not sealing on external sealing surface of mandrel.

FIGS. 54 through 62 schematically show steps of increasing the strokinglength of the mandrel when on a rig.

DETAILED DESCRIPTION

Detailed descriptions of one or more preferred embodiments are providedherein. It is to be understood, however, that the present invention maybe embodied in various forms. Therefore, specific details disclosedherein are not to be interpreted as limiting, but rather as a basis forthe claims and as a representative basis for teaching one skilled in theart to employ the present invention in any appropriate system, structureor manner.

During drilling, displacement, and/or completion operations it may bedesirable to perform down hole operations when the annular seal of anannular blow out preventer is closed on the drill string and rotationand/or reciprocation of the drill string is desired. One such operationcan be a frac (or fracturing) operation where pressure below the annularseal 71 is increased in an attempt to fracture the down hole formation.

FIGS. 1 and 2 show generally the preferred embodiment of the apparatusof the present invention, designated generally by the numeral 10.Drilling apparatus 10 employs a drilling platform S that can be afloating platform, spar, semi-submersible, or other platform suitablefor oil and gas well drilling in a deep water environment. For example,the well drilling apparatus 10 of FIGS. 1 and 2 and related method canbe employed in deep water of for example deeper than 5,000 feet (1,500meters), 6,000 feet (1,800 meters), 7,000 feet (2,100 meters), 10,000feet (3,000 meters) deep, or deeper.

In FIGS. 1 and 2, an ocean floor or seabed 87 is shown. Wellhead 88 isshown on seabed 87. One or more blowout preventers can be providedincluding stack 75 and annular blowout preventer 70. The oil and gaswell drilling platform S thus can provide a floating structure S havinga rig floor F that carries a derrick and other known equipment that isused for drilling oil and gas wells. Floating structure S provides asource of drilling fluid or drilling mud 22 contained in mud pit MP.Equipment that can be used to recirculate and treat the drilling mud caninclude for example a mud pit MP, shale shaker SS, mud buster orseparator MB, and choke manifold CM.

An example of a drilling rig and various drilling components is shown inFIG. 1 of U.S. Pat. No. 6,263,982 (which patent is incorporated hereinby reference). In FIGS. 1 and 2 conventional slip or telescopic jointSJ, comprising an outer barrel OB and an inner barrel IB with a pressureseal therebetween can be used to compensate for the relative verticalmovement or heave between the floating rig S and the fixed subsea riserR. A Diverter D can be connected between the top inner barrel IB of theslip joint SJ and the floating structure or rig S to control gasaccumulations in the riser R or low pressure formation gas from ventingto the rig floor F. A ball joint BJ between the diverter D and the riserR can compensate for other relative movement (horizontal and rotational)or pitch and roll of the floating structure S and the riser R (which istypically fixed).

The diverter D can use a diverter line DL to communicate drilling fluidor mud from the riser R to a choke manifold CM, shale shaker SS or otherdrilling fluid or drilling mud receiving device. Above the diverter Dcan be the flowline RF which can be configured to communicate with a mudpit MP. A conventional flexible choke line CL can be configured tocommunicate with choke manifold CM. The drilling fluid or mud can flowfrom the choke manifold CM to a mud-gas buster or separator MB and aflare line (not shown). The drilling fluid or mud can then be dischargedto a shale shaker SS, and mud pits MP. In addition to a choke line CLand kill line KL, a booster line BL can be used.

FIG. 2 is an enlarged view of the drill string or work string 85 thatextends between rig 10 and seabed 87 having wellhead 88. In FIG. 2, thedrill string or work string 85 is divided into an upper drill or workstring and a lower drill or work string. Upper string is contained inriser 80 and extends between well drilling rig S and swivel 100. Anupper volumetric section 90 is provided within riser 80 and in betweendrilling rig 10 and swivel 100. A lower volumetric section 92 isprovided in between wellhead 88 and swivel 100. The upper and lowervolumetric sections 90, 92 are more specifically separated by annularseal unit 71 that forms a seal against sleeve 300 of swivel 100. Annularblowout preventer 70 is positioned at the bottom of riser 80 and abovestack 75. A well bore 40 extends downwardly from wellhead 88 and intoseabed 87. Although shown in FIG. 2, in many of the figures the lowercompletion or drill string 85 has been omitted for purposes of clarity.

FIGS. 1 and 2 are schematic views showing oil and gas well drilling rig10 connected to riser 80 and having annular blowout preventer 70(commercially available). FIG. 2 is a schematic view showing rig 10 withswivel 100 separating. Swivel 100 is shown detachably connected toannular blowout preventer 70 through annular packing unit seal 71.

FIG. 4 includes a schematic diagram of one embodiment of a swivel tool100 which can rotate and/or stroke/reciprocate. With such constructiondrill or well string 85 can be rotated and/or stroked/reciprocated whileannular blowout preventer 70 is sealed around sleeve or housing 300 ofswivel tool 100. FIG. 3 is a drawing of the exterior of annular blow outpreventer 70.

Mandrel 110 is contained within a bore of sleeve 300. Swivel 100includes an outer sleeve or housing 300 having a generally verticallyoriented open-ended bore that is occupied by mandrel 110. Sleeve 300provides upper catch, shoulder or flange 326 and lower catch, shoulderor flange 328.

FIG. 6 is a perspective view of one embodiment of a swivel tool 100having a rotating and reciprocal sleeve 300 with sectional mandrel 110having joints incorporating pin end tip sealing configuration.Generally, the stroke length (relative longitudinal movement betweenmandrel 110 and sleeve 300) is equal to the length of the mandrel 110(Lm) minus the length of the sleeve (Ls).

FIG. 7 is a side view of the rotating and reciprocal swivel 100 wherethe sleeve 300 is located in its lowermost (and latched) position, andthe center of gravity of the swivel 100 is identified. In thisembodiment no sealing area recesses (e.g., 706, 906, etc. are shown).FIGS. 8A, 8B, and 8C are perspective views of the rotating andreciprocal swivel tool 100 where respectively the sleeve 300 is locatedin its lowermost (FIG. 8A), mid stroke (FIG. 8B), and upper most (FIG.8C) positions.

Without external sealing areas recesses, the overall length of mandrel110 may be limited to the height of the derrick of the rig because themandrel 110 will preferably be made up at the shop, as making it up inthe field will likely scratch/damage the sealing areas of mandrel 110.

FIG. 9 is a side view of made up mandrel 110 having joints incorporatingpin end tip sealing configuration of FIG. 6. FIG. 10 is a sectional viewof mandrel 110 having joints incorporating an inner diameter sealing aswill be described below. Mandrel 110 can be comprised of joints 500,600, 700, 800, 900, 1000, and 1100. Depending on the desired strokelength of mandrel 110, additional joints of mandrel can be used.

FIG. 12 is a sectional view of mandrel 110 showing a joints 600,700,800of mandrel 110 having two pin ends (joint 700) and two connecting joints(600,800) incorporating box/male by box/male connections, and includingsealing insert 1500 having an annular recess 1540 for seal 750. FIG. 11Ais a sectional view of a joint of mandrel 110 which incorporates theinner diameter sealing configuration using seal 750 which is containedin mating annular recesses 728 (of joint 700) and 1540 (of joint 600).FIG. 11B is an enlarged sectional view of the joint of FIG. 11A.

FIG. 13 is an end view of a seal 750 or 760 which can be used matingannular recesses 728 (of mandrel joint 700) and 1540 (of mandrel joint600). FIG. 14 is a sectional view of the seal 750. FIG. 15 is anenlarged sectional view of the seal 750. First seal 750 can comprisefirst end 752, widened area of first seal 753, second end of first seal755, tapered area of first seal 756, and vertical area of first seal757. Tapered areas 756,756′ can be used to assist second end 755 of seal750 to enter recess 1540 of insert 1500 when joint 700 is being threadedinto joint 600. Seal 750 can have inner sealing diameter 770 and outersealing diameter 774 (which are defined by vertical walls 757).

FIG. 16 is a sectional view of mandrel 110 showing the uppermostconnection joint (joint 600 threaded onto joint 500) incorporating pinend tip sealing configuration. Seal 550 can be of similar constructionto seal 750 shown in FIG. 13. Shoulder 570 can limit stroke length ofmandrel 110 relative to sleeve 300 when catch 326 contacts shoulder 570.

FIG. 17 is a sectional view of mandrel 110 showing the lowermostconnection joint (joint 1000 threaded onto joint 1100) incorporating pinend tip sealing configuration. Seal 1150 can be of similar constructionto seal 750 shown in FIG. 13. Shoulder 570 can limit stroke length ofmandrel 110 relative to sleeve 300 when locking shoulder 1200 limitsfurther movement of catch 328.

FIG. 18 is a sectional view of one box/female by box/female type joint600 of mandrel 100 showing a double female end connection joint forreceiving the pin end tip sealing configuration of one embodiment. FIG.19 is an enlarged view of a circumferential recess 1540′ for receivingthe seal (e.g., seal 750 shown in FIGS. 11 and 12). FIG. 20 is anenlarged view (Detail A) of an end shoulder 660 for limiting movement ofthe slidable sealing block 1500 of one embodiment.

FIG. 21 is a sectional view joint 600, but with the slidable sealingblocks 1500,1500′ omitted. FIG. 22 is an end view of the double femaleend connection joint 600.

FIG. 23 is a sectional side view of a slidable sealing block 1500. FIG.24 is an end view of the slidable sealing block 1500. On first end 1520,sealing block 1500 can include annular recess 1540, which itself caninclude tapered walls 1546, and vertical section 1544. Tapered walls1546 can be constructed to match/cooperate with the tapered areas of theseal (such as tapered area 756 of seal 750). Annular recess 1540 canhave nominal diameter 1550, with outer diameter 1552 and inner diameter1554 created by vertical walls 1544. Insert 1500 can include an axialpassage 1510 having at least one transitional portion 1534 to transitionfrom the larger diameter axial passages of the box/female by box/femalejoints (e.g., 600, 800, 1000 etc.) to the smaller diameter axial passesof the pin/male by pin/male joints (e.g., 700, 900, etc.).

FIG. 25 is a sectional view of a joint 700 of mandrel 110 having twomale/pin ends 720,730 and two connecting joints incorporating pin endtip sealing configuration (annular recesses 728 and 738 respectivelyholding first seal 750 and second seal 760). FIG. 26 is an enlarged viewof the threads 722 of one end 720 of double male end mandrel joint 700.

FIG. 26 is an enlarged view of one of the pin ends 720 of the mandreljoint 700 with attached seal 750 inserted into the annular recess 728.Seal 750 can be as described before and attached to annular recess 728.Joint 700 can include axial passage 710 (with diameter 712) and firstthreads 722 (on upper end connection 720) with second threads 732 (onlower end connection 730). Annular recess 728 can include enlarged area729 which cooperates and holds enlarged area 753 of seal 750. Annularrecess 738 can be constructed similarly with enlarged area 739.

It is noted that, when joint 700 is threaded into joints 600 and 800,seals 750 and 760 of joint 700 will both remain exterior to theprojected cross section of axial passage 710 with diameter 712, butinterior to the projected cross section of axial passage 610 withdiameter 612 and axial passage 810 with diameter 812.

FIG. 27 is a sectional view of the uppermost mandrel joint 500 ofmandrel 110, with joint 500 having a pin/male end 530 incorporating seal550 (which can be of the same configuration as seal 750 describedabove). Joint 500 can include shoulder 533 for limiting longitudinalmovement between sleeve 300 and mandrel 110. FIG. 28 is an enlarged viewof one of the pin end 530. Annular recess 538 can include enlarged area539 for holding in place seal 550. Second end 520 can include abox/female connection which can attach to additional non-mandrel stringjoints.

FIG. 29 is a sectional view of the lowermost mandrel joint 1100 ofmandrel 110, with the joint having a pin end (at end 1120) sealingconfiguration (seal 1150 which can be of the same construction as seal750 described above). FIG. 30 is left end view of joint 1100. FIG. 31 isa right end view of joint 1100. FIG. 32 is an enlarged view of the areashowing a pressure relief area 1400, for relaxing/relieving pressurebetween the interstitial space of the interior of the sleeve 300 and theexterior of the mandrel 110 (when sleeve 300 is in its lowermost andquick locked condition). FIG. 33 is a sectional view of the lowermostmandrel joint 1100. Seal 1150 on end 1120 and placed in recess 1128(being held by enlarged area 1129 cooperating with enlarged area 1153 ofseal 1150) can be used to seal between joint 1100 and the connectingbox/female by box/female joint 1000. FIG. 34 is an enlarged view of oneof ends 1120 of joint 1100.

Mandrel Joints Include Mating Tapers to Prevent Flaring of Box EndConnection

FIGS. 35 through 37 show three sequence steps making a connectionbetween a box/female end (end 630 of mandrel joint 600 being made up toend 720 of mandrel joint 700).

For purposes of clarity insert 1500 and seal 750 have been omitted fromthese drawings. Arrow 670 schematically indicates that joints 600 and700 are threadably connected to each other by rotation. As taperedshoulder 721 comes close to tapered end 621 of end 630 of joint 600, themating tapers 721,621 will tend to cause the edges of joint 600 to becompressed toward axial passageway 610, and not allow the ends of joint600 to flare out away from axial passageway 610 when joints 600,700 aremade up at higher torques.

Resistance to flaring of the box end connections keeps the exteriorsealing surface 601 of joint 600 flush with exterior sealing surface 701of joint 700. Such flushness/smoothness/levelness between matingexterior sealing surfaces (701 and 601, and by analogy the exteriorsealing surfaces of other adjoining mandrel 110 joints), facilitatesproper sealing between sleeve 300 and mandrel 110, along with increasingseal life of seal units 370,380 of sleeve 300.

In different embodiments the mating shoulders can have a tapered portionwith a taper at about 1, 2, 3, 4, 5, 6, 6.25, 7, 8, 9, 10, 12, 13, 14,15, and 20 degrees from a line perpendicular to the longitudinalcenterline of a joint. In various embodiments the tapers can be within arange of between about any two of the specified degrees. Mating taperscan have equal magnitude but opposite tapers or slopes.

FIGS. 38 through 42 show various embodiments of the pin/male by pin/malemandrel joint with recess in its exterior sealing surface.

FIG. 38 shows joints 600, 700, and 800 attached with exterior sealingsurfaces 601, 701, and 801. Joint 700 includes recess 706 in itsexterior sealing surface 701. Recess 706 can include upper transitionarea 740 and lower transition area 746. Transition areas can includesofter transition inserts 742 and 748 as described below. Althoughinserts 1500, 1500′, 1500″, and 1500′″ are shown interior seals 750 and760 have been omitted for clarity (but are intended to be used as shownin other embodiments for with interior sealing).

Additionally, a single piece pin by pin mandrel joint 700 is shown inFIGS. 38 to 55, however, it is contemplated that the pin by pin sub canbe two pieces (such as shown in FIGS. 54 through 62 where mandrel joint700 is comprised of joint 700′ having the recess 706 and being a box bypin join in combination with joint 700″ being a pin by pin joint thecombination being a pin by pin joint with recess 706).

FIGS. 39 through 42 show pin by pin mandrel joint 700 with recess 706.Recess 706 can include upper transition area 740 and lower transitionarea 746. Transition areas can include softer transition inserts 742 and748. Joint 700 can include tapered shoulders 723 and 733 as described inother embodiments.

FIG. 43 is a side view of a sleeve 300. FIG. 44 is a sectional view ofsleeve 300, with the sealing elements removed from its ends. FIG. 45 isan enlarged sectional view (Detail A) of an end of sleeve 300.

Mandrel is Shearable for Ram Blow Out Preventer Regardless of VerticalPosition of Mandrel

The wall thickness 604, 804, 1004, etc. of box end joints 600, 800,1000, etc. will be such that the walls can be sheared by one of the rams2010, 2020, 2030, and/or 2040 of plurality of stacked ram blow outpreventers 2000.

The preferred wall thickness for 604, 804, 1004, etc. can be selectedfrom the set of thicknesses in inches less than about 1, 15/16, ⅞,13/16, ¾, 11/16, 10/16, 9/16, 8/16, 7/16, 6/16, 5/16, 4/16, 3/16, and ¼.In various embodiments the wall thickness can be between any two of thespecified thicknesses.

In one embodiment the spacing between double pin subs 700, 900, etc. issuch that at any one point in time only one of such subs 700, 900,and/or another double pin sub can be aligned with a ram of a pluralityof stacked ram blow out preventers.

FIG. 4 is a sectional view cut through the annular 70 and ram 2040 blowout preventers with the annular seal 71 closed on the sleeve 300 of therotating and reciprocating swivel 100. Mandrel 110 which comprisesmandrel joints 600, 800, 1000 connected together by double pin subs 700,900 are also schematically shown in FIG. 4.

Schematically shown in FIG. 4 is the spacing L₂ between subs 700 and 800is such that at any one point in time only one of subs 700 or 900 can bealigned with a ram of a ram blow out preventer 2000. Plurality ofstacked ram blow out preventers 2000 can include rams 2010, 2020, 2030,and 2040. Distance 2050 is between rams 2010 and 2020. Distance 2052 isbetween rams 2010 and 2030. Distance 2054 is between rams 2030 and 2040.Distance 2056 is between rams 2020 and 2040. Distance 2058 is betweenrams 2020 and 2030.

In this embodiment none of the distances 2050, 2052, 2054, 2056, and/or2058 can fall within the range of:

L₁+/−(L₄+L₆) (as shown in FIGS. 4 and 5).

In this manner there is no possibility that more than one ram (2010,2020, 2030, and/or 2040) can land on a double pin sub 700, 900, etc.,regardless of the amount of longitudinal stroking reciprocation ofmandrel 110 relative to sleeve 300, or the longitudinal position ofmandrel 110 relative to ram blow out preventer 2000 (assuming thatsleeve 300 is not positioned in ram blow out preventer 2000).

In one embodiment the length of any double box end joint 600, 800, 1000etc. is greater than at least about 4 feet. In other embodiments thelength is at least greater than about 5, 6, 7, 8, 9, 10, 12, 14, 15, 16,18, 20, 25, 30, 35, and 40 feet. In other embodiments the length isbetween any two of the above specified lengths.

The wall thickness 604, 804, 1004, etc. of double box end joints 600,800, 100, etc. will be such that the walls can be sheared by one of therams 2010, 2020, 2030, and/or 2040 of ram blow out preventer 2000.

Swivel 100 can be comprised of mandrel 110 and sleeve or housing 300.Sleeve or housing 300 can be rotatably, strokably/reciprocably, and/orsealably connected to mandrel 110. Accordingly, when mandrel 110 isrotated and/or reciprocated sleeve or housing 300 can remain stationaryto an observer insofar as rotation and/or reciprocation is concerned.Sleeve or housing 300 can fit over mandrel 110 and can be rotatably,reciprocably, and sealably connected to mandrel 110.

Sleeve or housing 300 can be rotatably connected to mandrel 110 by oneor more bushings and/or bearings, preferably located on opposedlongitudinal ends of sleeve or housing 300.

Sleeve or housing 300 can be sealingly connected to mandrel 110 by a oneor more seals (e.g., packing units 370 and 380), preferably spaced apartand located on opposed longitudinal ends of sleeve or housing 300. Theseals can seal the gap 315 between the interior 310 of sleeve or housing300 and the exterior of mandrel 110.

Sleeve or housing 300 can be reciprocally connected to mandrel 110through the geometry of mandrel 110 which can allow sleeve or housing300 to slide relative to mandrel 110 in a longitudinal direction (suchas by having a longitudinally extending distance H_(T) of the exteriorsurface of mandrel 110 a substantially constant diameter).

Swivel 100 can be made up of mandrel 110 to fit in line of a drill orwork string 85 and sleeve or housing 300 with a seal and bearing systemto allow for the drill or work string 85 to be rotated and reciprocatedat swivel 100 where annular seal unit 71 is closed on sleeve 300. Thiscan be achieved by locating swivel 100 in the annular blow out preventer70 where annular seal unit 71 can close around sleeve or housing 300forming a seal between sleeve or housing 300 and annular seal unit 71.

The amount of reciprocation (or stroke) can be controlled by thedifference between the height H_(T) of mandrel 110 and the length Ls ofthe sleeve or housing 300. As shown in FIG. 6, the stroke of swivel 100can be the difference between height H_(T) of mandrel 110 and length 350of sleeve or housing 300.

FIGS. 7 and 8 show a sectional view through the sleeve 300 and mandrel110. In one embodiment sealing units 370 and 380 can be two way seals.One advantage of using two sets of sealing units 370 and 380 which eachseal in opposite longitudinal directions is that the sleeve 300 andmandrel 110, even where one or more of the double pin subs (e.g., 700,900, etc.) with its recessed portion (e.g., 706, 906, etc.) is passingthrough the sealing unit, the spaced apart sealing unit can still sealagainst fluid flow. This backup sealing ability assists in maintainingsealing during vertical movement of mandrel 110 relative to sleeve 300.

Maintaining Sealing Between Mandrel and Sleeve During Rotation and/orStroking/Reciprocation where Mandrel Includes One or More Recessed Areasin its Exterior Sealing Surface

FIGS. 46 through 51 schematically illustrating stroking/reciprocatingmotion of sleeve or housing 300 relative to mandrel 110. In thisembodiment mandrel 110 can have one or more recessed areas (e.g., 706,906, etc.) in its exterior sealing surfaces (e.g., 601, 701, 801, 901,1001, etc.) but still maintain a seal between sleeve/housing 300 andmandrel 110.

Sealing is maintained notwithstanding sleeve 300 (and one of the sealingunits) passing over one of the recessed areas in the external sealingsurface of mandrel 110 by the remaining spaced apart sealing unit stillmaintaining a seal between sleeve 300 and mandrel 110. In thisembodiment sleeve 300 includes spaced apart sealing units 370,380located respectively under catches 326,328.

In these figures arrows 3000,3001,3002,3003, 3004, and 3005schematically indicate downward movement of mandrel 110 relative tosleeve 300. Additionally, arrows 3010,3011,3012,3013, 3014, and 3015schematically indicate upward movement of mandrel 110 relative to sleeve300.

The height L_(m) of mandrel 110 compared to the overall length L_(s) 350of sleeve or housing 300 can be configured to allow sleeve or housing300 to stroke/reciprocate (e.g., slide up and down) relative to mandrel110. FIGS. 46 through 51 are schematic diagrams illustratingstroking/reciprocation and/or rotation between sleeve or housing 300along mandrel 110 (allowing reciprocation and/or rotation between drillor work string 85 when annular seal 71 of annular blow out preventer 70is closed and sealed on sleeve 300, and drill or work string 85, therebysealing the bore hole from above—with the sleeve being closed in annularblow out preventer being shown in FIG. 2).

In FIGS. 46 through 51 (in such order) with arrows 3000, 3001, 3002,3003, 3004 and 3005 schematically indicate a downward stroke of mandrel110 relative to sleeve 300 in the direction of arrow 3000. In FIGS. 46through 51 (in reverse order of FIG. 51 down to FIG. 46) with arrows3010, 3011, 3012, 3013, 3014, and 3015 schematically indicate an upwardstroke of mandrel 110 relative to sleeve 300. During stroking of mandrel110 relative to sleeve 300, packing units 370 and 380 maintain a sealbetween sleeve 300 and mandrel 110, while annular seal 71 maintains aseal on sleeve 300 thereby sealing wellbore 40.

In FIGS. 46 and 47, arrows 3000,3001 schematically indicate that mandrel110 is moving downward relative to sleeve or housing 300, where a doublepin end sub 900 is located above the level of upper catch 326 (and upperpacking unit 370) of sleeve 300. While upper packing unit 370 may notmaintain a seal when double pin end sub 900 passes through (e.g.,recessed area 906 causing a break in the sealing between packing unit370 and sub 900 as shown in FIG. 52B), lower packing unit 380 (in lowercatch 328) maintains a seal between sleeve 300 and mandrel 110 (as shownin FIG. 53A), while annular seal 71 of annular blow out preventer 70maintains a seal on sleeve 300 thereby sealing wellbore 40.

In FIG. 48, arrow 3002 schematically indicates that mandrel 110continues to stroke downwardly relative to sleeve or housing 300, wherea double pin end sub 900 (and recess 906) is located between upper catch321 (and upper packing unit 370) and lower catch 328 (and lower packingunit 380). Now both packing units 370 and 380 maintain a seal betweensleeve 300 and mandrel 110 (as shown in FIGS. 52A and 53A), whileannular seal 71 maintains a seal on sleeve 300 thereby sealing wellbore40.

In FIG. 49, arrow 3003 schematically indicates that mandrel 110continues to stroke downwardly relative to sleeve or housing 300, wherenow a double pin end sub 900 is located at the level of lower catch 328(and lower packing 380 unit) of sleeve 300. While packing unit 380 maynot maintain a seal when recess 906 of double pin end sub 900 passesthrough (e.g., recessed area 906 causing a break in the sealing as shownin FIG. 53B), upper packing unit 370 maintains a seal between sleeve 300and mandrel 110 (as shown in FIG. 52A), while annular seal 71 maintainsa seal on sleeve 300 thereby sealing wellbore 40.

FIGS. 50 and 51 schematically indicate continued downwardly stroking ofmandrel 110 through sleeve or housing 300 wherein the next recessedjoint (double pin sub 700 with recessed area 706) will pass throughsleeve 300. The spaced apart sealing units 370 and 380 of sleeve willeither jointly or singularly maintain a seal between sleeve 300 andmandrel 110 when one of these sealing units passes over the recessedarea (similar to that described with FIGS. 46 through 49 regarding joint900 and recess 906). In FIG. 50 both packing units 370 and 380 maintaina seal between sleeve 300 and mandrel 110 (as shown in FIGS. 52A and53A), while annular seal 71 maintains a seal on sleeve 300 therebysealing wellbore 40. In FIG. 51, while packing unit 370 may not maintaina seal when double pin end sub 700 passes through (e.g., recessed area706 causing a break in the sealing as shown in FIG. 52B), packing unit380 maintains a seal between sleeve 300 and mandrel 110 (as shown inFIG. 53A), while annular seal 71 maintains a seal on sleeve 300 therebysealing wellbore 40.

On the other hand, an upward stroking movement of mandrel 110 throughsleeve 300 is schematically indicated by arrows3015,3014,3013,3012,3011, and 3010 in the reverse order of FIGS. 51through 46.

In the above described manner a seal can be maintained between mandrel110 and sleeve 300 notwithstanding various recesses in the sealing areaof mandrel 110 that sleeve 300 sees during relativestroking/reciprocation movement of mandrel 110 relative to sleeve 300.

Adjusting Stroking Length of Mandrel—Double Box End Mandrel can be ofDifferent Heights which can be Made Up on the Rig

FIG. 5 shows is a swivel tool 100 with mandrel 110 and sleeve 300. FIG.5 is a schematic view of one embodiment of a mandrel 110 which includesa plurality of double box end joints (600, 800, 1000) connected by aplurality of double pin end subs (700, 900).

The overall stroking height H_(T) of double box mandrel 110 can be equalto the sum of the lengths of the joints and subs making it up. In thiscase the overall height H_(T) of mandrel 110 is equal to L₁+L₂+L₃+L₄+L₆.To change the overall height H_(T) (to be either more or less) differentnumbers of mandrel joints 600, 800, 1000 can be used to make up mandrel110. Another way to change the overall height H_(T) of mandrel 110 is touse mandrel joints 600, 800, 1000 of different lengths.

Double box end joint 600 can be of a length L_(I), and can includelongitudinal passage with a box connection at its upper end 620 alongwith box connection at its lower end 630.

Double box end joint 800 can be of a length L₂, and can includelongitudinal passage with a box connection at its upper end 820 alongwith box connection 850 at its lower end 830.

Double box end joint 1000 can be of a length L₃, and can includelongitudinal passage 1010 (not shown) with a box connection at its upperend 1020 along with box connection at its lower end 1030.

Double pin sub 700 can comprise upper end 720, lower end 730 along withlongitudinal passage 710. Sub 700 can also include upper shoulder 723,lower shoulder 733, and recessed area 706.

Recessed area 706 can be used for supporting mandrel 110 after joints600, 800, 1000, etc. have been connected to each other forming mandrel110. Supporting mandrel 110 using one of the recessed areas of themandrel without gripping the sealing surfaces of joints 600,800,1000,etc. for supports prevents such surfaces from being scratched and/ordamaged thus causing problems or failure of a seal between mandrel 110and sleeve 300 (i.e., sealing with seal units 370 and/or 380).Additionally, supporting mandrel 110 using one of the recessed areas inthe double pin subs, where such subs are damaged, allows replacement ofthe subs 700, 900, etc., while protecting (and preventing therequirement to replace) the more expensive double box end mandrel jointpieces 600, 800, 1000, etc.

Box connection of lower end 630 for joint 600 can be threadablyconnected to upper end 710 of double pin sub 700. Box connection of theupper end 820 of mandrel joint 800 can be threadably connected to lowerend 730 of double pin sub 700.

FIG. 5 is a close up sectional and schematic view of the connectionsbetween three double box end joints 600, 800, 1000 and two double pinend subs 700, 900. Here mandrel joints 600, 800, and 1000 are beingconnected using double pin end subs 700 and 900.

Double pin sub 900 can comprise upper end 920, lower end 930 along withlongitudinal passage 910. Sub 900 can also include upper shoulder 923,lower shoulder 933, and recessed area 906.

Box connection as the lower end 630 of joint 600 can be threadablyconnected to upper end 720 of double pin sub 700. Box connection at theupper end 820 of mandrel joint 800 can be threadably connected to lowerend 730 of double pin sub 700.

Box connection at the lower end 830 of joint 800 can be threadablyconnected to upper end 910 of double pin sub 900. Box connection at theupper end 1020 of mandrel joint 1000 can be threadably connected tolower end 930 of double pin sub 900.

Now, recessed areas 706, or 906 can be used for supporting made upmandrel 110 after joints 600, 800, 1000, etc. have been connected toeach other forming mandrel 110. Supporting mandrel 110 in the recessedareas 706,906 (i.e., non-sealing areas) without grabbing onto thesealing surfaces of joints 600,800,1000, etc. prevents such surfacesfrom being scratched and/or damaged thus causing problems or failure ofa seal between mandrel 110 and sleeve 300 (i.e., sealing with seal units370 and/or 380).

In one embodiment, mandrel 110 of swivel tool 100 can be at leastpartially lengthened while being tripped downhole.

FIGS. 54 through 62 show various steps of adjusting the stroking lengthof mandrel 110 while at the rig. These are schematic figures where inall cases the stroking length of mandrel 110 is contemplated as beingsubstantially straight in the longitudinal direction although theschematic drawings may have copying errors which appear to indicate apartially bent mandrel 110.

In one embodiment is provided a method of determining the strokinglength of a rotating and reciprocable swivel tool 100 at a drilling rigor platform having a floor, comprising the steps of:

(a) providing a swivel tool 100, the swivel tool 100 comprising amandrel 110 and a sleeve 300, the mandrel 110 being rotatable andreciprocable relative to the sleeve/housing 300, the mandrel 110 havinga first stroke length relative to the sleeve/housing (shown in FIG. 54);

(b) supporting in a substantially vertical direction the swivel tool 100at the rig 10 (shown in FIG. 54 where tool 100 is supported by rigelevators on rig floor using recessed area 906);

(c) adding a mandrel joint to the top of the mandrel 110, suchadditional joint increasing the stroking length of the mandrel 110relative to the first stoking length (shown in FIG. 55 where the mandreljoint is selected from a plurality of mandrel joints such as those shownin FIG. 56—the made up mandrel 110′ is shown in FIG. 57);

(d) lowering the swivel tool and again supporting in a verticaldirection the swivel tool in a substantially vertical direction on therig (schematically shown between FIGS. 54 and 57 with the down arrowand, in FIG. 57 mandrel 110′ is supported by elevator using recess 706);and

(e) repeating steps “c” and “d” until the final stroking length of themandrel 110 relative to the sleeve/housing is at least 100 feet.

In various embodiments the steps “c” and “d” can be repeated until thefinal stroking length can be greater than about 100, 150, 200, 250, 300,350, 400, 450, 500, 550, 600, 700, 800, 900, 1000, 1200, 1400, 1500,1600, 1800, and 2000 feet, or any stroke lengths between any two of thespecified stroke lengths.

In various embodiments a plurality of the mandrel joints include arecessed areas (e.g., 706, 906, etc.) in the exterior sealing surface,and during step “c” the one of these recessed areas are used to supportthe swivel tool in a substantially vertical direction.

In one embodiment the plurality of recessed areas can include softmaterial transition sections.

In various embodiments the upper portions of the recessed areas can befrustoconical.

In various embodiments the upper portions of the recessed areas can betapered.

One embodiment comprises a method of increasing stroke length of mandrelwhile located on rig or platform.

One embodiment comprises a method of making up the mandrel while on rigor platform.

Well-Bore Fracturing

In one embodiment swivel tool 100 can be used in well bore fracturingprocess.

“Hydraulic fracturing,” sometimes simply referred to as “fracturing,” isa common stimulation treatment. A treatment fluid for this purpose issometimes referred to as a “fracturing fluid.” The fracturing fluid ispumped at a high flow rate and high pressure down into the wellbore andout into the formation. The pumping of the fracturing fluid is at a highflow rate and pressure that is much faster and higher than the fluid canescape through the permeability of the formation. Thus, the high flowrate and pressure creates or enhances a fracture in the subterraneanformation.

Creating a fracture means making a new fracture in the formation.Enhancing a fracture means enlarging a pre-existing fracture in theformation.

For pumping in hydraulic fracturing, a “frac pump” is used, which is ahigh-pressure, high-volume pump. Typically, a frac pump is apositive-displacement reciprocating pump. These pumps generally arecapable of pumping a wide range of fluid types, including corrosivefluids, abrasive fluids and slurries containing relatively largeparticulates, such as sand. Using a frac pump, the fracturing fluid maybe pumped down into the wellbore at high rates and pressures, forexample, at a flow rate in excess of 100 barrels per minute (3,100 U.S.gallons per minute) at a pressure in excess of 5,000 pounds per squareinch (“psi”). The pump rate and pressure of the fracturing fluid may beeven higher, for example, pressures in excess of 10,000 psi are notuncommon.

To fracture a subterranean formation typically requires hundreds ofthousands of gallons of fracturing fluid. Further, it is often desirableto fracture at more than one downhole location. For various reasons,including the high volumes of fracturing fluid required, readyavailability, and historically low cost, the fracturing fluid is usuallywater or water-based. Thus, fracturing a well may require millions ofgallons of water.

When the formation fractures or an existing fracture is enhanced, thefracturing fluid suddenly has a fluid flow path through the crack toflow more rapidly away from the wellbore. As soon as the fracture iscreated or enhanced, the sudden increase in flow of fluid away from thewell reduces the pressure in the well. Thus, the creation or enhancementof a fracture in the formation is indicated by a sudden drop in fluidpressure, which can be observed at the well head.

After it is created, the newly-created fracture will tend to close afterthe pumping of the fracturing fluid is stopped. To prevent the fracturefrom closing, a material must be placed in the fracture to keep thefracture propped open. This material is usually in the form of aninsoluble particulate, which can be suspended in the fracturing fluid,carried downhole, and deposited in the fracture. The particulatematerial holds the fracture open while still allowing fluid flow throughthe permeability of the particulate. A particulate material used forthis purpose is often referred to as a “proppant.” When deposited in thefracture, the proppant forms a “proppant pack,” and, while holding thefracture apart, provides conductive channels through which fluids mayflow to the wellbore. For this purpose, the particulate is typicallyselected based on two characteristics: size range and strength.

During wellbore fracturing operations the annular blowout preventer 70is closed to maintain pressure while fracturing operations areperformed. However, during fracturing operations the string ofpiping/tubing/drill string 85 is moved longitudinally and/or rotatedrelative to the closed annual blow out preventer 70.

However, this vertical movement creates a problem with extremefrictional drag involved with closing the annular blowout preventer 70rubber seal element 71 on the drill pipe 85. The reason this is aproblem is that during wellbore fracturing the drill pipe 85 must bestripped upwards through the closed annular seal 71 which tends todamage to the annular seal 71. Damage risks increase where tool joints(i.e., portions of the string having larger diameters) are strippedthrough the closed annular seal 71.

In one embodiment, for a fracturing job, the number of zones and lengthsof each zone can be identified in order to determine the amount ofstroke length required for a fracturing job. In this embodiment, swiveltool 100 can be used in string 85 where the annular blow out 70preventer is closed on sleeve 300. In this embodiment the length of themandrel 110 required to achieve the required stroke length for overalltraversing of formation zones between mandrel 110 and sleeve 300 can becalculated.

There is long felt but unsolved need to have a swivel tool 100 includinga mandrel 110 that can be made up to a desired length while at the rig10 to accommodate fracturing operations. There is long felt but unsolvedneed to have a swivel tool 100 including a mandrel 110 that is shearablerelative to a plurality of stacked ram type blow out preventers 2000regardless of the position of the mandrel 110 relative to the stack ofram type blow out preventers 2000.

In one embodiment the mandrel 110 can be configured to a predeterminedlength off site from the well 10 to be fractured to the length requiredto achieve the calculated stroke length required, and then mandrel 110is transported to rig 10.

In one embodiment the mandrel 110 can be made up onsite at rig 10,during the tripping in process, to a predetermined selected strokelength for the well to be fractured to achieve the calculated requiredstroke length.

Example Fracturing Job:

If 1,000 foot stroke length is calculated as being required for a job tocover the estimated zones, the actual stroke length of the mandrel 110can include a 50% factor of safety for stroke length making the nominalstroke length of 1,500 feet. This factor of safety can be used toaccount for possible miscalculations while spacing out.

In one embodiment, the swivel tool 100 with stroking mandrel 110 can bepartially made up at a site remote from rig 10. In one embodiment swiveltool 100 partially being made up includes the bottom latch sub 1100 andat least one stroking mandrel joint 1000 with the sleeve/housing 300being slidably connected to this mandrel 110 and placed in a quick lockcondition for transport.

On the top of the mandrel 110 will be a pin by box elevator sub 160. Inaddition a plurality of mandrel joints are included (both box by box andpin by pin).

Below the swivel can be the bottom hole assembly for performing downholefracturing operations.

In one embodiment the rotating and reciprocating swivel tool 100 can belowered from the rig floor F into the riser 80. In one embodiment thesleeve/housing 300 is lowered in a quick locked condition relative tomandrel 110.

In one embodiment, as the swivel tool 100 is being lowered the strokelength of the swivel tool 100 can be increased to a desired strokelength. As the swivel tool 100 is being lowered additional joints ofmandrel 110 can be added to the mandrel 110 to obtain the desired strokelength between the sleeve/housing 300 and the mandrel 110. After thenumber of joints of mandrel 110 to obtain the desired stroke length areattached the makeup of the swivel tool 100 is completed by attaching thelimiting sub 500 (with limiting shoulder 570) to the top of made upmandrel 110 thereby creating the desired stroke length.

The swivel tool 100 is continued to be lowered by now adding joints ofpipe (e.g., drill pipe) while lowering the entire string 85. After this,during the continued process of lowering the swivel tool 100, joints ofpiping/tubing/drill string can be added while the swivel tool 100 isbeing lowered to where the annular blow out preventer 70 (i.e., annularseal) is closed on the sleeve 300.

In one embodiment the swivel tool 100 is lowered until thesleeve/housing 300 has passed below the annular blow out preventer 70,and then the sealing element 71 of the annular blow out preventer 70 isat least partially closed on mandrel 110 before the swivel tool 100 israised slowly until the top of the sleeve/housing 300 contacts thebottom of the sealing element 71 of the annular blow out preventer 70.

Next, the sealing element 71 is opened and the sleeve/housing 300 israised and positioned such that the external sealing area (e.g., thearea between catches 326,328) of the sleeve/housing 300 is locatedadjacent the sealing element 71 of the annular blow out preventer 70,and the sealing element 71 of the annular blow out preventer 70 is atleast partially closed on the sealing area of the sleeve 300.

Next, the sleeve/housing 300 is raised until the base of the lower catch328 contacts the bottom of the sealing element 71. Next, the sealingelement 71 is fully closed on the sealing surface of the sleeve 300.

Next the string 85 (including mandrel 110) is lowered relative to thesleeve/housing 300 to longitudinally unlock the sleeve/housing 300relative to the mandrel 110.

Next, downhole operations can be begun while the sealing element 71 ofthe annular blow out preventer 70 remains sealed against thesleeve/housing 300.

During these subsequent downhole operations the mandrel 110 (andattached string 85) can be stroked and/or rotated relative to thesleeve/housing 300 without the closed sealing element 71 of the annularblow out preventer 70 seeing any differential movement therebyprotecting the sealing element 71 from damage.

Once the sleeve/housing 300 of the swivel tool 100 is located in theclosed annular blow out preventer 70, downhole operations (e.g.,fracturing operations) can be started by lowering the 1,500 foot strokelength of the mandrel 110 from its uppermost stroke position (where thesleeve/housing 300 is in its longitudinally locked position) to anydesired lower position of the attached wellbore fracturing tools (up tothe mandrel's lowermost stroking position where sleeve contacts shoulder570). The longitudinal movement of the mandrel 110 (and attached string85) relative to the sleeve 300 can be at the operator's desired speed,and can include rotation of the mandrel 110 (and attached string 85)relative to the sleeve/housing 300 if desired by the operator.

Once the wellbore fracturing tools are in place then the zones of theformation can be isolated relative to the fracturing tool (byconventional methods) and fracturing pumping can commence.

Once the sand slurry (with contained proppant) is completely pumped intothe zone to be fractured, pumping can be stopped, and the wellborefracturing tools with attached string 85 and mandrel 110 lifted up thewellbore 40 to the next zone. During this step the stroking mandrel 110is raised relative to the sleeve/housing 300 which sleeve/housing 300 iscontinued to be sealed upon by the annular sealing element 70.

Once the tools are located in the next zone above then, the sameoperation of pumping is repeated for each zone moving up the wellbore40.

Benefits of the swivel tool 100 include but are not limited to:

(1) no differential movement between the annular seal 71 and any itembeing raised or lowered in the wellbore 40 while the annular seal 71remains closed on the sleeve/housing 300;

(2) no stripping of tool joints through a closed annular blowoutpreventer 70.

Once multiple zones have been fractured, the job is complete, while theseal 71 remains closed on sleeve 300, mandrel 110 can be raised relativeto the sleeve/housing 300 until the sleeve/housing 300 enters a latchedstate at the upper portion of the stroke length of the mandrel 110.Next, the sealing element 71 of the annular blow out preventer 70 can beopened and the swivel tool 100 with attached string 85 tripped out ofthe hole 40.

Equipment Needed to Run Special Drill Pipe

-   -   Box/female by box/female joints (e.g., 600, 800, 1000, etc.) of        mandrel 110 of tubular/piping (which preferably are about 30        feet in overall length).    -   Pin/male by pin/male mandrel tubular/piping tool joints (e.g.,        700, 900, etc.) of tubular/piping (which preferably are about 30        inches in overall length, and include a recessed elevator groove        e.g., 706, 906, etc.)    -   Pup joints (e.g. joint 2100 in FIGS. 54, 55, 58, and 51) for        lifting and handling the mandrel 110 during make-up and        break-out at rig 10.    -   False rotary    -   2-sets of special 5″ elevators    -   Special non-scaring make-up tongs    -   Hand operated strap tongs    -   Stabbing guide    -   Hand file    -   Scouring pads    -   Cleaning solvents    -   Dope

While certain novel features of this invention shown and describedherein are pointed out in the annexed claims, the invention is notintended to be limited to the details specified, since a person ofordinary skill in the relevant art will understand that variousomissions, modifications, substitutions and changes in the forms anddetails of the device illustrated and in its operation may be madewithout departing in any way from the spirit of the present invention.No feature of the invention is critical or essential unless it isexpressly stated as being “critical” or “essential.”

The following is a parts list of reference numerals or part numbers andcorresponding descriptions as used herein:

LIST FOR REFERENCE NUMERALS Reference Numeral Description 10 drillingrig/well drilling apparatus 22 drilling fluid or mud 40 well bore 70annular blowout preventer 71 annular seal unit 75 stack 80 riser 85drill or work string 87 seabed 88 well head 90 upper volumetric section92 lower volumetric section 100 swivel 110 mandrel 126 upper end 128lower end 300 swivel sleeve or housing 310 interior section 315 gap 326upper catch, shoulder, flange 328 lower catch, shoulder, flange 350 Ls -overall length of sleeve or housing with attachments on upper and lowerends 370 first seal 380 second seal 500 upper stroke limiting mandreljoint 510 longitudinal passage 512 diameter of longitudinal passage 520upper end 522 threads 530 lower end 532 threads 533 tapered shoulder 538recess for seal 539 enlarged area of recess for seal 550 seal 552 firstend 553 widened area of seal 555 second end of seal 556 tapered area ofseal 557 vertical area of seal 570 shoulder 600 double box end mandreljoint 601 exterior sealing surface 602 interior surface 604 wallthickness 610 longitudinal passage 612 inner diameter 620 upper end 621tapered shoulder 622 threads 623 tapered area 630 lower end 632 threads633 tapered area 660 shoulder 670 arrow 672 arrow 700 double pin endmandrel joint 701 exterior sealing surface 704 wall thickness 706recessed area 710 longitudinal passage 712 diameter 720 upper end 721tapered shoulder 722 threads 723 tapered shoulder 728 recess for firstseal 729 widened area of first recess 730 lower end 731 tapered shoulder732 threads 733 tapered shoulder 738 recess for second seal 739 widenedarea of second recess 740 upper taper 742 transition insert 746 lowertransition 748 transition insert 750 first seal 752 first end 753widened area of first seal 755 second end of first seal 756 tapered areaof first seal 757 vertical area of first seal 760 second seal 770 innerdiameter 774 outer diameter 800 double box end mandrel joint 801exterior sealing surface 802 interior surface 804 wall thickness 810longitudinal passage 812 inner diameter 820 upper end 830 lower end 850seal 900 double pin end mandrel joint 901 exterior sealing surface 906recessed area 910 longitudinal passage 920 upper end 923 taperedshoulder 930 lower end 933 tapered shoulder 1000 double box end mandreljoint 1001 exterior sealing surface 1004 wall thickness 1010longitudinal passage 1012 inner diameter 1020 upper end 1030 lower end1100 lower shouldered mandrel joint 1110 longitudinal passage 1112 innerdiameter 1120 upper end 1122 threads 1128 recess for seal 1129 enlargedarea of recess for seal 1130 lower end 1132 threads 1150 seal 1153widened area of seal 1155 second end of seal 1156 tapered area of seal1157 vertical area of seal 1200 limiting shoulder 1300 locking shoulder1400 recessed area for relaxing internal pressure between sleeve andmandrel 1500 female adjustable sealing unit 1502 exterior surface 1510longitudinal passage 1520 first end 1522 reduced inlet 1530 second end1532 enlarged inlet 1534 tapered section 1540 recess for seal 1544vertical section 1546 tapered area 1550 diameter of recess 1552 outerdiameter of recess 1554 inner diameter of recess 1560 O-ring recess 1562O-ring 2000 plurality of ram blow out preventers 2010 first ram blow outpreventer 2012 arrow 2020 second ram blow out preventer 2022 arrow 2030third ram blow out preventer 2032 arrow 2040 fourth ram blow outpreventer 2042 arrow 2050 distance between first and second rams 2052distance between first and third rams 2054 distance between third andfourth rams 2056 distance between second and fourth rams 2058 distancebetween second and third rams 2100 lifting sub 2500 double pin endmandrel joint 2506 recessed area in external sealing surface 2600 doublebox end mandrel joint 2700 double pin end mandrel joint 2706 recessedarea in external sealing surface 2800 double box end mandrel joint 2900double pin end mandrel joint 2906 recessed area in external sealingsurface 3000 double box end mandrel joint 3001 arrow indicating downwardmovement 3002 arrow indicating downward movement 3003 arrow indicatingdownward movement 3004 arrow indicating downward movement 3005 arrowindicating downward movement 3010 arrow indicating upward movement 3011arrow indicating upward movement 3012 arrow indicating upward movement3013 arrow indicating upward movement 3014 arrow indicating upwardmovement 3015 arrow indicating upward movement 3100 double pin endmandrel joint 3106 recessed area in external sealing surface ABOPannular blow out preventer BJ ball joint BL booster line CM chokemanifold CL choke line CM choke manifold D diverter DL diverter line Frig floor IB inner barrel KL kill line MP mud pit MB mud gas buster orseparator OB outer barrel R riser RAM BOP ram blow out preventer RF flowline S floating structure or rig SJ slip or telescoping joint SS shaleshaker

All measurements disclosed herein are at standard temperature andpressure, at sea level on Earth, unless indicated otherwise. Allmaterials used or intended to be used in a human being arebiocompatible, unless indicated otherwise.

It will be understood that each of the elements described above, or twoor more together may also find a useful application in other types ofmethods differing from the type described above. Without furtheranalysis, the foregoing will so fully reveal the gist of the presentinvention that others can, by applying current knowledge, readily adaptit for various applications without omitting features that, from thestandpoint of prior art, fairly constitute essential characteristics ofthe generic or specific aspects of this invention set forth in theappended claims. The foregoing embodiments are presented by way ofexample only; the scope of the present invention is to be limited onlyby the following claims.

1. A method of creating a rotating and reciprocating swivel tool whilelocated on a drilling rig or platform having a specified stroke length,comprising the steps of: (a) providing a swivel tool, the swivel toolcomprising a mandrel and a sleeve/housing, the mandrel being rotatableand reciprocable relative to the sleeve/housing, the mandrel having afirst stroke length relative to the sleeve/housing; (b) supporting in asubstantially vertical direction the swivel tool at the rig; (c) addinga mandrel joint to the top of the mandrel, such additional jointincreasing the stroking length of the mandrel relative to the firststoking length; (d) lowering the swivel tool and again supporting in avertical direction the swivel tool in a substantially vertical directionon the rig; and (e) repeating steps “c” and “d” until the final strokinglength of the mandrel relative to the sleeve/housing is at least 100feet.
 2. The method of claim 1, wherein steps “c” and “d” can berepeated until the final stroking length can be greater than about 150feet. 3-6. (canceled)
 7. The method of claim 1, wherein in step “e” aplurality of the mandrel joints include at least one recessed area inthe exterior sealing surface, and during step “c” one of these recessedareas are used to support the swivel tool in a substantially verticaldirection on the rig.
 8. The method of claim 7, wherein at least one ofthe recessed areas includes soft material transition sections.
 9. Themethod of claim 7, wherein the upper portions of the recessed areas arebe frustoconical.
 10. The method of claim 7, wherein the upper portionsof the recessed areas are tapered. 11-27. (canceled)
 28. A joint andseal ring assembly for joining and sealing threaded pipe or tube endsthat define an axial flow passage therethrough, comprising: first andsecond ends, each of the ends being at a respective one of the tubeends; the axial flow passage having first and second internal diameters;each end having opposed end faces with side walls cooperating to definean annular recess comprising a seal chamber and a circumferentiallycontinuous groove opening radially inward from the seal chamber to theaxial flow passage, the radial groove being positioned between the firstand second internal diameters of the axial flow passage; a gasketcomprising a main body and a radially inward second portion in theuncompressed state; and the main body of the gasket being positionedwithin the seal chamber.
 29. The assembly of claim 28, wherein thegasket is resilient.
 30. The assembly of claim 28, wherein the main bodyof the gasket in an uncompressed state has an inner radius equal to orless than the inner radius of the seal chamber wall forming aninterference fit occurs. 31-32. (canceled)
 33. A method of using areciprocating swivel in a drill or work string, the method comprisingthe following steps: (a) lowering a rotating and reciprocating tool toan annular blow out preventer, the tool comprising a mandrel and asleeve, the sleeve being reciprocable relative to the mandrel and themandrel including at least one joint having double box ends with thejoint being severable by a ram blow out preventer, the sleeve having twospaced apart sealing units, the swivel including an interstitial spacebetween the sleeve and the mandrel with first and second spaced apartsealing units each sealing the interstitial space; (b) after step “a”,having the annular blow out preventer close on the sleeve; and (c) afterstep “b”, causing relative longitudinal movement between the sleeve andthe mandrel.
 34. The method of claim 33, wherein in step “a” the mandrelincludes two double box end joints which are connected by a double pinend sub, and in step “c” when the double pin end sub is at the samelongitudinal position as the first sealing unit, the first sealing unitloses its seal of the interstitial space, but the second sealing keepsits seal of the interstitial space.
 35. The method of claim 34, whereinafter the double pin end sub passes by the first sealing unit, the firstsealing unit regains its seal of the interstitial space.
 36. The methodof claim 35, wherein when the double pin end sub is at the samelongitudinal position as the second sealing unit, the second sealingunit loses its seal of the interstitial space, but the first sealingkeeps its seal of the interstitial space.
 37. The method of claim 36,wherein after the double pin end sub passes by the second sealing unit,the second sealing unit regains its seal of the interstitial space. 38.The method of claim 33, wherein in step “a” the mandrel includes twodouble box end joints which are connected by a double pin end sub, andin step “c” when the double pin end sub is at the same longitudinalposition as the second sealing unit, the second sealing unit loses itsseal of the interstitial space, but the first sealing keeps its seal ofthe interstitial space.
 39. The method of claim 38, wherein after thedouble pin end sub passes by the second sealing unit, the second sealingunit regains its seal of the interstitial space.
 40. The method of claim39, wherein when the double pin end sub is at the same longitudinalposition as the first sealing unit, the first sealing unit loses itsseal of the interstitial space, but the second sealing keeps its seal ofthe interstitial space. 41-45. (canceled)